Method for increasing efficiency and reducing emissions in a steam reforming plant

ABSTRACT

A method for decreasing the SFFC of a steam reforming plant, including establishing a base operating mode. Then modifying the base operating mode by introducing the shift gas stream into a solvent based, non-cryogenic separator prior to introduction into the pressure swing adsorption and introducing the compressed hydrogen depleted off-gas stream in a membrane separation unit, wherein the membrane is configured to produce the hydrogen enriched permeate stream at a suitable pressure to allow the hydrogen enriched permeate stream to be combined with carbon dioxide lean shift gas stream, prior to introduction into the pressure swing adsorption unit without requiring additional compression. Thereby establishing a modified operating mode. Wherein said pressure swing adsorption unit has a modified overall hydrogen recovery. Wherein said modified operating mode has a modified hydrogen production, a modified hydrogen production unit firing duty, a modified SCO2e, and a modified SFFC.

BACKGROUND

In hydrogen plant design and operation, a primary objective is tominimize specific feed and fuel consumption (SFFC), defined herein asBTU of feedstock and fuel per standard cubic foot of hydrogen. Otherthan selection of the appropriate syngas generating technology andrelated process parameters, there are two other primary steps whichminimize SFFC and therefore maximize hydrogen yield: the water gas shiftstep and the pressure swing adsorption step.

A secondary objective may be to reduce carbon dioxide emissions of thehydrogen plant on a specific basis, SCO2e, defined herein as tons of CO2emitted per standard cubic foot of hydrogen produced. As a rule ofthumb, 55-65% of the CO2 emitted is generated in the syngas generationstep and water gas shift step(s), where the balance is generated bycombustion of hydrocarbon fuels to provide heat for the syngasgeneration step. It is known generally in the prior art that CO2 captureis less expensive on a syngas stream than on a flue gas stream, which isnot considered in this filing. It is also known generally in the priorart that solvent based non cryogenic CO2 removal units such asamine-based technologies or Rectisol™ are the industrial standard fortreating such streams.

The water gas shift step maximizes hydrogen yield by converting carbonmonoxide, produced in the syngas generation step, and water, toadditional hydrogen and carbon dioxide. There are different types ofwater gas shift reactors, whereas the “high temperature” water gas shiftis most commonly used in hydrogen plants.

Further conversion of carbon monoxide to hydrogen can occur when a “hightemperature” water gas shift is preceding a “low temperature” water gasshift. This is more commonly used in ammonia plants, where it isrequired that the carbon monoxide is reduced as low as possible. Abyproduct of any water gas shift step is carbon dioxide, in addition tothe amount produced in the syngas generation step.

The Pressure Swing Adsorption (PSA) step follows water gas shift and isresponsible for separating as much produced hydrogen out of the syngasstream as possible. The typical recovery in a syngas plant is 80-90% ofthe hydrogen, which means at least 10-20% of hydrogen produced is notrecovered. The non-recovered hydrogen, as well as any non-hydrogencomponents, comprise the PSA offgas, which is most commonly used as fuelin the Plant. The main component of the PSA offgas is carbon dioxide(usually 40-50 mol %), followed by any lost hydrogen, and othercomponents like residual carbon monoxide, methane, nitrogen, and water.

SUMMARY

A method for decreasing the SFFC and SCO2e and increasing the SCO2c of asteam reforming plant, including establishing a base operating mode.Then modifying the base operating mode by introducing the shift gasstream into a solvent based, non-cryogenic separator prior tointroduction into the pressure swing adsorption unit, thereby producinga saturated carbon dioxide stream, and a carbon dioxide lean shift gasstream, combining the carbon dioxide lean shift gas stream with ahydrogen enriched permeate stream and introducing the combined gasstream into the pressure swing adsorption unit, thereby producing amodified hydrogen product stream, which contains not more than 90% ofthe total hydrogen produced by the syngas generation and water gas shiftsteps, and a hydrogen depleted off-gas stream, which contains not lessthan 10% of the total hydrogen contained within the shift gas stream,wherein the hydrogen depleted off-gas stream is compressed to a pressuregreater than 25 psi greater than the hydrocarbon stream pressure, andintroducing the compressed hydrogen depleted off-gas stream in amembrane separation unit, thereby producing a hydrogen enriched permeatestream and a hydrogen depleted retentate stream, wherein the membrane isconfigured to produce the hydrogen enriched permeate stream at asuitable pressure to allow the hydrogen enriched permeate stream to becombined with carbon dioxide lean shift gas stream, prior tointroduction into the pressure swing adsorption unit without requiringadditional compression, and wherein the hydrogen depleted retentatestream is combined with the hydrocarbon stream prior to admission intothe steam methane reformer as the process feed stream. Therebyestablishing a modified operating mode. Wherein said pressure swingadsorption unit has a modified overall hydrogen recovery. Wherein saidmodified operating mode has a modified hydrogen production, a modifiedhydrogen production unit firing duty, a modified SCO2e, and a modifiedSFFC. Wherein the modified SCO2e is at least 7% less than the baseSCO2e. Wherein the modified SCO2c is at least 12% greater than the baseSCO2c.

BRIEF DESCRIPTION OF THE FIGURES

For a further understanding of the nature and objects for the presentinvention, reference should be made to the following detaileddescription, taken in conjunction with the accompanying drawings, inwhich like elements are given the same or analogous reference numbersand wherein:

FIG. 1 is a schematic representation in accordance with one embodimentof the present invention.

ELEMENT NUMBERS

-   -   101=process feed stream    -   102=high pressure steam stream    -   103=hydrogen production unit    -   104=hydrocarbon stream    -   105=fuel gas stream    -   106=raw syngas stream    -   107=flue gas stream    -   108=high temperature water-gas shift converter    -   109=low temperature water-gas shift converter    -   110=shifted syngas stream    -   111=syngas cooler    -   112=cooled, shifted syngas stream    -   113=solvent based, non-cryogenic separator    -   114=carbon dioxide depleted shift gas stream    -   115=pressure swing adsorption unit    -   116=hydrogen product stream    -   117=off-gas stream    -   118=off-gas stream compressor    -   119=membrane separation unit    -   120=hydrogen rich permeate stream    -   121=hydrogen depleted retentate stream    -   122=saturated carbon dioxide stream    -   123=flash gas stream    -   124=first fraction (of flash gas stream)    -   125=second fraction (of flash gas stream)    -   128=segment (of hydrogen product stream)    -   129=portion (of process feed stream)

DESCRIPTION OF PREFERRED EMBODIMENTS

Illustrative embodiments of the invention are described below. While theinvention is susceptible to various modifications and alternative forms,specific embodiments thereof have been shown by way of example in thedrawings and are herein described in detail. It should be understood,however, that the description herein of specific embodiments is notintended to limit the invention to the particular forms disclosed, buton the contrary, the intention is to cover all modifications,equivalents, and alternatives falling within the spirit and scope of theinvention as defined by the appended claims.

It will of course be appreciated that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming, but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

Described herein are methods for decreasing the specific feed and fuelconsumption (SFFC) (BTU HHV of feed and fuel per standard cubic foot ofhydrogen) and/or decreasing specific CO2 emissions (SCO2e) (as definedas tons of CO2 emitted per standard cubic feet of hydrogen produced)and/or increasing specific CO2 capture (SCO2c) (as defined as tons ofCO2 captured per standard cubic feet of hydrogen produced) in a new orexisting hydrogen plant. These methods include compression of thepressure swing adsorption off-gas which contains hydrogen not recoveredby any other process unit, processing of the compressed off-gas by amembrane unit, recycling without additional compression of the hydrogenrich stream from the membrane unit to the inlet of the pressure swingadsorption unit for further hydrogen purification, and recycling withoutadditional compression of the hydrogen depleted stream from the membraneas a feed of the syngas generation unit.

A so-called “base operating mode” may be defined as introducing aprocess a process feed stream into a hydrogen production unit and thusproduce a raw syngas stream. This raw syngas stream is the introducedinto a high temperature water gas shift converter, thus producing ashifted syngas steam. This shifted syngas stream may then be introducedinto a pressure swing adsorption unit which produces a product hydrogenstream. This “base operating mode” will have a base overall hydrogenrecovery, a base hydrogen production, a base hydrogen production unitfiring duty, a base SCO1e, a base SCO2c, and a base SFFC against whichthe following improvements will be gauged.

Turning to the sole FIGURE, process feed stream 101 is combined withhigh-pressure steam stream 102 and introduced into hydrogen productionunit 103. In one embodiment, process feed stream may be combined withhydrocarbon stream 104, which may consist of hydrocarbons of C2 andhigher. Hydrocarbon stream 104 may include, but not be limited to,ethane, propane, butanes, or naphtha. Introduction of these higherhydrocarbons would tend to maximize SCO2c from the syngas and optimizeCO2 capture costs and revenues.

Hydrogen production unit 103 is preferably a steam methane reformer,which may be combined with a waste heat boiler (not shown). Fuel gasstream 105 is also introduced into hydrogen production unit 103, whichthus produces raw syngas stream 106 and flue gas stream 107. Raw syngasstream 106 is then introduced into high temperature water gas shiftreactor 108, and optionally then into low temperature water gas shiftreactor 109, thus producing shifted syngas steam 110. Within hightemperature water gas shift reactor 108 and/or low temperature water gasshift reactor 109, carbon monoxide and steam are catalytically convertedinto carbon dioxide and hydrogen. Shifted syngas stream 110 is thenintroduced into syngas cooler 111, which produces cooled, shifted syngasstream 112.

Cooled, shifted syngas stream 112 is then introduced into solvent basednon-cryogenic separator 113, wherein at least a fraction of the CO2present is removed prior to admission into pressure swing adsorptionunit 115. In one embodiment, solvent based non-cryogenic separator 113is an amine unit. This is the most economical location from which torecover CO2. An alternate, but more expensive option being removal ofCO2 from the furnace flue gas, which is not considered herein. Solventbased non-cryogenic separator 113 produces saturated CO2 stream 122 andshift gas stream 114 that is largely depleted of CO2. Saturated CO2stream 122 may be captured and utilized for some downstream purpose. Assaturated CO2 stream 127 is purposed as to not be emitted to theatmosphere, the SCO2e is reduced by not less than 50% compared to the“base operating mode”, but preferably by not less than 60%.

Solvent based non cryogenic separator 113 may also have a flash step,thereby producing flash gas stream 123. Flash gas stream 123 may have apressure of not more than 200 psig, and preferably not more than 30psig. Flash gas stream 123 may contain CO2, hydrogen, carbon monoxide,and methane. At least a first fraction 124 of flash gas stream 123 maybe combined with off-gas stream 117, prior to admission into off-gasstream compressor 118. Combining first fraction 124 with off-gas stream117 thereby decreases SCO2e by not less than 15% when compared to theprior art. Combining first fraction 124 with off-gas stream 117 therebyincreases SCO2c by not less than 20% compared to the prior art. A secondfraction 125 of flash gas stream 123 may be combined with a segment 128of hydrogen product stream 116, and/or a portion 129 of process feedstream 101, prior to admission into hydrogen product ion unit 103 as acombined fuel stream.

Shift gas stream 114 may be combined with hydrogen rich permeate stream120 (below), and the combined stream is introduced into pressure swingadsorption unit 115. Pressure swing adsorption unit 115 produceshydrogen product stream 116 and off-gas stream 117. The recycling ofhydrogen rich (i.e. CO2 depleted) permeate stream 120 this way, providesa steady state operation of the iterative system that yields an overallhydrogen recovery for pressure swing adsorption unit 115 of not lessthan 98 mol %, and preferably not less than 99 mol %, an increase of notless than 10 base points compared to the “base operating mode” or a newplant designed without the instant invention.

Thus, any CO2 that may have been present in the feed stream to pressureswing adsorption unit 115 in the absence of solvent based non-cryogenicseparator 113 is now largely absent from the PSA unit off-gas. Off-gasstream 117 is now mostly hydrogen (typically up to 65%). The lack of CO2in off-gas stream 117 stream allows it to be economically compressed foradditional hydrogen recovery. Hydrogen product stream 116 may containless than 90% of the total hydrogen produce by hydrogen production unit103, high temperature water gas shift reactor 108, and (if present) lowtemperature water gas shift reactor 109. Conversely, off-gas stream 117contains at least 10% of the total hydrogen produce by hydrogenproduction unit 103, high temperature water gas shift reactor 108, and(if present) low temperature water gas shift reactor 109.

Off-gas stream 117 is then introduced into off-gas stream compressor118, wherein it is compressed and sent to membrane separation unit 119.Off-gas stream compressor 118 may compress off-gas stream 117 to notless than 25 psi less than the pressure of hydrocarbon stream 104.Membrane separation unit 119 separates at least 50%, but preferably atleast 70%, of the hydrogen in off-gas stream 117 from the othercomponents (CO, CO2 (trace), CH4, N2, H2O). The resulting hydrogen richpermeate stream 120 comprises up to 98 mol % H2. Membrane separationunit 119 is designed in such a way that hydrogen rich permeate stream120 is of suitable pressure to be recycled back to the inlet pressureswing adsorption unit 115 in order to further purify up to 99.9 mol %H2, without further compression.

The net effect is an overall recovery of up to 99 mol % of the hydrogenproduced, a 11-23% increase depending on the baseline PSA performance.This reduces the plant's SFFC. Membrane separation unit 119 may recovernot less than 50 mol % of the hydrogen contained in the off-gas stream117, and preferably not less than 70 mol %. Membrane permeate stream 120may have not less than 50 mol % hydrogen purity, and preferably not lessthan 70 mol %. Residual hydrogen depleted retentate stream 121 is mostlyCO, CH4, and CO2 with some amount of N2 and water. Some unseparated H2remains in the hydrogen depleted retentate stream 121. Hydrogen depletedretentate stream 121 may be combined with process feed stream 101.

In one embodiment, this system may be added to existing plants. Existingplants which recover the additional hydrogen can also produce the sameamount of hydrogen product as previously, but at a reduced reformerload, decreasing both SFFC and SCO2e depending on the configuration. Theconcept is suitable for existing plants which want to make additionalhydrogen (i.e. “H2 boost”), or for new plants where the syngasgeneration step could be reduced in size and cost due to the increasedhydrogen recovery downstream.

In another embodiment, the additional hydrogen recovered may be used asa fuel to decarbonize the fuel system. In this case, the plant may runat full firing duty, and burn the hydrogen produced above originaldesign. Utilization of this additional hydrogen recovery allows for thesame hydrogen production in an existing plant for a decreased firingduty, thereby decreasing SFFC by not less than 2% compared to “baseoperating mode”, preferably by not less than 3%.

In another embodiment, the additional hydrogen recovery may allow for ahigher hydrogen production, for the same firing duty, not less than 10%more, preferably by not less than 15% more compared to prior art. Theadditional hydrogen recovery may allow for a smaller and cheaper syngasgeneration step with a lower firing duty in a new plant, for the samedesired hydrogen production, compared to prior art.

In another embodiment, the additional hydrogen recovery may allow forthe same hydrogen production in an existing plant at the same firingduty, allowing for some percentage of hydrogen product to be used as acarbon free fuel, thereby decreasing SCO2e by not less than 30% comparedto the prior art, and increasing SCO2c by not less than 40% compared tothe prior art.

It will be understood that many additional changes in the details,materials, steps and arrangement of parts, which have been hereindescribed in order to explain the nature of the invention, may be madeby those skilled in the art within the principle and scope of theinvention as expressed in the appended claims. Thus, the presentinvention is not intended to be limited to the specific embodiments inthe examples given above.

What is claimed is:
 1. A method for decreasing the SFFC and SCO2e andincreasing the SCO2c of a steam reforming plant, comprising: a.introducing a hydrocarbon stream and a steam stream into a steam methanereformer, thereby producing a raw syngas stream, wherein the hydrocarbonstream has a hydrocarbon stream pressure, b. introducing the raw syngasstream into a high temperature water gas shift converter, therebyproducing a shift gas stream, and c. introducing the shift gas streaminto a pressure swing adsorption unit, thereby producing a hydrogenproduct stream thereby establishing a base operating mode, wherein saidpressure swing adsorption unit has a base overall hydrogen recovery,wherein said base operating mode has a base hydrogen production, a basehydrogen production unit firing duty, a base SCO2e, a base SCO2c, and abase SFFC, the method further comprising: d. introducing the shift gasstream into a solvent based, non-cryogenic separator prior tointroduction into the pressure swing adsorption unit, thereby producinga saturated carbon dioxide stream, and a carbon dioxide lean shift gasstream, e. combining the carbon dioxide lean shift gas stream with ahydrogen enriched permeate stream and introducing the combined gasstream into the pressure swing adsorption unit, thereby producing amodified hydrogen product stream, which contains not more than 90% ofthe total hydrogen produced by the syngas generation and water gas shiftsteps, and a hydrogen depleted off-gas stream, which contains not lessthan 10% of the total hydrogen contained within the shift gas stream,wherein the hydrogen depleted off-gas stream is compressed to a pressuregreater than 25 psi greater than the hydrocarbon stream pressure, f.introducing the compressed hydrogen depleted off-gas stream in amembrane separation unit, thereby producing a hydrogen enriched permeatestream and a hydrogen depleted retentate stream, wherein the membrane isconfigured to produce the hydrogen enriched permeate stream at asuitable pressure to allow the hydrogen enriched permeate stream to becombined with carbon dioxide lean shift gas stream, prior tointroduction into the pressure swing adsorption unit without requiringadditional compression, and wherein the hydrogen depleted retentatestream is combined with the hydrocarbon stream prior to admission intothe steam methane reformer as the process feed stream, therebyestablishing a modified operating mode, wherein said pressure swingadsorption unit has a modified overall hydrogen recovery, wherein saidmodified operating mode has a modified hydrogen production, a modifiedhydrogen production unit firing duty, a modified SCO2e, and a modifiedSFFC wherein the modified SCO2e is at least 7% less than the base SCO2e,wherein the modified SCO2c is at least 12% greater than the base SCO2c.2. The method of claim 1, wherein the modified overall hydrogen recoveryfor the pressure swing adsorption unit is not less than 98 mol % or animprovement of not less than 10 base points over the base overallhydrogen recovery.
 3. The method of claim 2, wherein the modifiedoverall hydrogen recovery for the pressure swing adsorption unit is notless than 99 mol %.
 4. The method of claim 1, wherein the differencebetween the modified hydrogen production and the base hydrogenproduction comprises a delta hydrogen recovery, wherein the differencebetween the modified hydrogen production unit firing duty and the basehydrogen production unit firing duty comprises a delta hydrogenproduction unit firing duty.
 5. The method of claim 4, wherein the basehydrogen production may be achieved with the modified operating mode byreducing the base hydrogen production unit firing duty by the deltahydrogen production unit firing duty, thereby a modified SFFC that isnot less than 1% lower than the base SFFC.
 6. The method of claim 5,wherein the modified SFFC that is not less than 2% lower than the baseSFFC.
 7. The method of claim 1, wherein the syngas stream is introducedinto a low temperature water gas shift reactor following the hightemperature water gas shift reactor and prior to introduction to thesolvent based, non-cryogenic separator, thereby reducing the off-gasstream carbon dioxide content and increasing the syngas carbon dioxidecontent.
 8. The method of claim 7, wherein the solvent basednon-cryogenic separator produces a flash gas at not more than 200 psig,containing CO2, hydrogen, carbon monoxide, and methane, which iscombined with the hydrogen depleted off-gas stream, thereby producing afurther modified SCO2e, wherein the further modified SCO2e is at least8% less than the base SCO2e, and producing a modified SCO2c, wherein themodified SCO2c is at least 5% less than the base SCO2C.
 9. The method ofclaim 8, wherein the flash gas has a pressure of not more than 30 psig.10. The method of claim 7, wherein at least a portion of modifiedhydrogen product stream is combined with the hydrocarbon stream andintroduced into the steam methane reformer as the fuel gas stream,thereby resulting in a further modified SCO2e, wherein the furthermodified SCO2e is at least 20% less than the base SCO2e, and producing amodified SCO2C, wherein the modified SCO2c is at least 20% greater thanthe base SCO2C.
 11. The method of claim 7, wherein the hydrocarbonfeedstock is more carbon rich than methane, thereby maximizing the SCO2cfrom syngas.
 12. The method of claim 1, wherein the modified hydrogenproduction is achieved with the base hydrogen production unit firingduty, and wherein the modified hydrogen production is at least 10%greater than the base hydrogen production.
 13. The method of claim 12,wherein the modified hydrogen production is at least 15% greater thanthe base hydrogen production.
 14. The method of claim 1, wherein themembrane separation unit recovers more than 50 mol % of the hydrogencontained in the hydrogen depleted off-gas steam.
 15. The method ofclaim 14, wherein the membrane unit recovers at least 70% of thehydrogen contained in the hydrogen depleted off-gas steam.
 16. Themethod of claim 1, wherein the hydrogen enriched permeate stream atleast 50 mol % hydrogen.
 17. The method of claim 16, wherein thehydrogen enriched permeate stream is at least 70 mol % hydrogen purity.18. The method of claim 1, wherein the modified SCO2e is at least 9%less than the base SCO2e.
 19. The method of claim 1, wherein themodified SCO2c is at least 14% greater than the base SCO2c.